Method and Apparatus for NMR Measurements While Drilling with Multiple Depths of Investigation

ABSTRACT

NMR spin echo signals are measured in a borehole during drilling. Signals measured in a plurality of regions of investigation with different depths of investigation in the borehole are processed to give a radial profile of formation properties, including a potential gas kick.

CROSS-REFERENCE TO RELATED APPLICATIONS

This applications claims priority from U.S. Provisional PatentApplication Ser. No. 61/176,791 filed on May 8, 2009. The application isalso related to US patent applications being filed concurrently with thepresent application titled “A method and apparatus for NMR measurementsin underbalanced drilling” under Attorney Docket No. NMR4-49302-US, andtitled “A method and apparatus for NMR measurements while drilling insmall boreholes” under Attorney Docket No. NMR4-50756-US.

BACKGROUND OF THE DISCLOSURE

1. Field of the Disclosure

The present disclosure relates generally to determining geologicalproperties of subsurface formations using Nuclear Magnetic Resonance(“NMR”) methods for logging wellbores, particularly for correcting forthe effects of fluid flow during underbalanced drilling on NMR signals.

2. Description of the Related Art

A variety of techniques are currently utilized in determining thepresence and estimation of quantities of hydrocarbons (oil and gas) inearth formations. These methods are designed to determine formationparameters, including among other things, the resistivity, porosity andpermeability of the rock formation surrounding the wellbore drilled forrecovering the hydrocarbons. Typically, the tools designed to providethe desired information are used to log the wellbore. Much of thelogging is done after the well bores have been drilled. More recently,wellbores have been logged while drilling, which is referred to asmeasurement-while-drilling (MWD) or logging-while-drilling (LWD).

One commonly used technique involves utilizing Nuclear MagneticResonance (NMR) logging tools and methods for determining, among otherthings, porosity, hydrocarbon saturation and permeability of the rockformations. The NMR logging tools are utilized to excite the nuclei ofthe fluids in the geological formations surrounding the wellbore so thatcertain parameters such as nuclear spin density, longitudinal relaxationtime (generally referred to in the art as T₁) and transverse relaxationtime (generally referred to as T₂) of the geological formations can bemeasured. From such measurements, porosity, permeability and hydrocarbonsaturation are determined, which provides valuable information about themake-up of the geological formations and the amount of extractablehydrocarbons.

The NMR tools generate a static magnetic field in a region of interestsurrounding the wellbore. NMR is based on the fact that the nuclei ofmany elements have angular momentum (spin) and a magnetic moment. Thenuclei have a characteristic Larmor resonant frequency related to themagnitude of the magnetic field in their locality. Over time the nuclearspins align themselves along an externally applied static magnetic fieldcreating a macroscopic magnetization, in short: magnetization. Thisequilibrium situation can be disturbed by a pulse of an oscillatingmagnetic field, which tips the spins with resonant frequency within thebandwidth of the oscillating magnetic field away from the static fielddirection. The angle θ through which the spins exactly on resonance aretipped is given by the equation:

θ=γB ₁ t _(p)/2  (1)

where γ is the gyromagnetic ratio, B₁ is the magnetic flux densityamplitude of the sinusoidally oscillating field and t_(p) is theduration of the RF pulse.

After tipping, the magnetization precesses around the static field at aparticular frequency known as the Larmor frequency ω₀ given by

ω₀=γB₀  (2)

where B₀ is the static magnetic flux density. For hydrogen nucleiγ/2π=4258 Hz/Gauss, so that a static field of 235 Gauss would produce aprecession frequency of 1 MHz. At the same time, the magnetizationreturns to the equilibrium direction (i.e., aligned with the staticfield) according to a characteristic recovery time known as the“spin-lattice relaxation time” or T₁. T₁ is controlled by the molecularenvironment and is typically one millisecond to several seconds inrocks.

At the end of a θ=90° tipping pulse, spins on resonance are pointed in acommon direction perpendicular to the static field, and they precess atthe Larmor frequency. However, because of inhomogeneity in the staticfield due to the constraints on tool shape, imperfect instrumentation,or microscopic material heterogeneities, each nuclear spin precesses ata slightly different rate. Hence, after a time long compared to theprecession period, but shorter than T₁, the spins will no longer beprecessing in phase. This de-phasing occurs with a time constant that iscommonly referred to as T₂*. Dephasing due to static field inhomogeneitycan be recovered by generating spin echoes (see below). The remainingdephasing is characterized by the time constant T₂ and is due toproperties of the material.

A receiving coil is designed so that a voltage is induced by theprecessing spins. Only that component of the nuclear magnetizationprecesses that is orthogonal to the static magnetic field. Theprecessing component induces a signal in the receiving coil if itsorientation is appropriate. After a 180° tipping pulse (an “inversionpulse”), the spins on resonance are aligned opposite to the static fieldand the magnetization relaxes along the static field axis to theequilibrium direction. Hence, a signal will be generated after a 90°tipping pulse, but not after a 180° tipping pulse in a generally uniformmagnetic field.

While many different methods for measuring T₁ have been developed, asingle standard known as the CPMG sequence (Carr-Purcell-Meiboom-Gill)for measuring T₂ has evolved. In contrast to laboratory NMR magnets,well logging tools have inhomogeneous magnetic fields due to theconstraints on placing the magnets within a tubular tool and theinherent “inside-out” geometry. Maxwell's divergence theorem dictatesthat there cannot be a region of high homogeneity outside the tool.Therefore in typical well bores, T₂*<<T₂, and the free induction decaybecomes a measurement of the apparatus-induced inhomogeneities. Tomeasure the true T₂ in such situations, it is necessary to cancel theeffect of the apparatus-induced inhomogeneities. To accomplish the same,a series of pulses is applied to repeatedly refocus the spin system,canceling the T₂* effects and forming a series of spin echoes. The decayof echo amplitude is a true measure of the decay due to materialproperties. Furthermore it can be shown that the decay is in factcomposed of a number of different decay components forming a T₂distribution. The echo decay data can be processed to reveal thisdistribution which is related to rock pore size distribution and otherparameters of interest to the well log analyst.

Normally, drilling operations are carried out with a mud weight selectedso that the fluid pressure in the borehole is slightly greater than theformation fluid pressure. Potential risks associated with normaldrilling are formation damage (when borehole fluid flows uncontrollablyinto the formation) and lost circulation. The problem of lostcirculation can be particularly acute in highly fractured carbonatereservoirs. In underbalanced drilling, the fluid pressure in theborehole is less than the formation pore pressure. By maintaining theunderbalanced state, the risk of formation damage is reduced and lostcirculation will not happen. In addition, an increased rate ofpenetration (ROP) is possible and, in addition, the risk of differentialsticking is also reduced.

When underbalanced drilling is done, there will be inflow of formationfluid into the borehole. The amount of fluid inflow depends on fluidviscosity, formation permeability and pressure difference betweenborehole and formation. In certain cases substantial fluid-velocitiescan be expected. The flow is in radial direction towards the boreholewall. The NMR measurements of conventional NMR tools with high radialmagnetic field gradient will be influenced by the motion of the fluidmolecules towards the borehole. The present disclosure addresses thisproblem of fluid inflow.

SUMMARY OF THE DISCLOSURE

One embodiment of the disclosure is an apparatus configured to evaluatean earth formation. The apparatus includes: a carrier configured to beconveyed in a borehole in the earth formation; a magnet assembly on thecarrier configured to produce a static magnetic field in the earthformation and define a plurality of regions at different radial distancefrom the borehole; at least one antenna on the carrier configured to beactivated with at least one pulse sequence, the at least one pulsesequence configured to produce a signal from nuclear spins from anassociated one of the plurality of regions of examination; and aprocessor configured to estimate a value of a property of the earthformation at the different radial distances using the produced signalfrom each of the plurality of regions of examination.

Another embodiment of the disclosure is a method of evaluating an earthformation. The method includes: conveying a carrier into a borehole inthe earth formation; using a magnet assembly on the carrier forproducing a static magnetic field in the earth formation and defining aplurality of regions at different radial distance from the borehole;activating at least one antenna on the carrier with at least one pulsesequence, the at least one pulse sequence configured to produce a signalfrom nuclear spins from an associated one of the plurality of regions ofexamination; and using a processor for estimating a value of a propertyof the earth formation at the different radial distances using theproduced signal from each of the plurality of regions of examination.

Another embodiment of the disclosure is a computer-readable mediumproduct having stored thereon instructions that when executed by aprocessor cause the processor to execute a method. The method includes:estimating a value of a property of the earth formation at each of aplurality of regions of examination at different radial distances from aborehole using signals produced signal from each of the plurality ofregions of examination responsive to activation of at least one antennawith at least one pulse sequence, the at least one pulse sequenceconfigured to produce a signal from nuclear spins from an associated oneof the plurality of regions of examination.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood with reference to theaccompanying figures in which like numerals refer to like elements andin which:

FIG. 1 shows a measurement-while-drilling tool suitable for use with thepresent disclosure;

FIG. 2 shows a sensor section of a measurement-while-drilling devicesuitable for use with the present disclosure;

FIG. 3 shows an NMR sensor having multiple regions of examination;

FIG. 4( a) shows an NMR sensor having axially spaced apart multipleregions of examination of different depths into the formation;

FIG. 4( b) shows an NMR sensor having multiple regions of examination ofdifferent depths into the formation a the same axial depth;

FIG. 5 shows three different regions of examination from which T₂distributions are obtained and shown schematically by 501, 503 and 505in (a), (b) and (c), and the estimate NMR porosity versus depth ofinvestigation shown in (e);

FIG. 6 shows a flow chart for estimating different formation propertiesusing NMR measurements from different depths of investigation; and

FIGS. 7( a)-(e) shows different hardware configurations to reduce theradial field gradient.

DETAILED DESCRIPTION OF THE DISCLOSURE

FIG. 1 shows a schematic diagram of a drilling system 10 with adrillstring 20 carrying a drilling assembly 90 (also referred to as thebottomhole assembly, or “BHA”) conveyed in a “wellbore” or “borehole” 26for drilling the wellbore. The drilling system 10 includes aconventional derrick 11 erected on a floor 12 which supports a rotarytable 14 that is rotated by a prime mover such as an electric motor (notshown) at a desired rotational speed. The drillstring 20 includes atubing such as a drill pipe 22 or a coiled-tubing extending downwardfrom the surface into the borehole 26. The drillstring 20 is pushed intothe wellbore 26 when a drill pipe 22 is used as the tubing. Forcoiled-tubing applications, a tubing injector, such as an injector (notshown), however, is used to move the tubing from a source thereof, suchas a reel (not shown), to the wellbore 26. The drill bit 50 attached tothe end of the drillstring breaks up the geological formations when itis rotated to drill the borehole 26. If a drill pipe 22 is used, thedrillstring 20 is coupled to a drawworks 30 via a Kelly joint 21, swivel28, and line 29 through a pulley 23. During drilling operations, thedrawworks 30 is operated to control the weight on bit, which is animportant parameter that affects the rate of penetration. The operationof the drawworks is well known in the art and is thus not described indetail herein. For the purposes of this disclosure, it is necessary toknow the axial velocity (rate of penetration or ROP) of the bottomholeassembly. Depth information and ROP may be communicated downhole from asurface location. Alternatively, the method disclosed in U.S. Pat. No.6,769,497 to Dubinsky et al. having the same assignee as the presentapplication and the contents of which are incorporated herein byreference may be used. The method of Dubinsky uses axial accelerometersto determine the ROP. During drilling operations, a suitable drillingfluid 31 from a mud pit (source) 32 is circulated under pressure througha channel in the drillstring 20 by a mud pump 34. The drilling fluidpasses from the mud pump 34 into the drillstring 20 via a desurger (notshown), fluid line 38 and Kelly joint 21. The drilling fluid 31 isdischarged at the borehole bottom 51 through an opening in the drill bit50. The drilling fluid 31 circulates uphole through the annular space 27between the drillstring 20 and the borehole 26 and returns to the mudpit 32 via a return line 35. The drilling fluid acts to lubricate thedrill bit 50 and to carry borehole cutting or chips away from the drillbit 50. A sensor S₁ typically placed in the line 38 provides informationabout the fluid flow rate. A surface torque sensor S₂ and a sensor S₃associated with the drillstring 20 respectively provide informationabout the torque and rotational speed of the drillstring. Additionally,a sensor (not shown) associated with line 29 is used to provide the hookload of the drillstring 20.

In one embodiment of the disclosure, the drill bit 50 is rotated by onlyrotating the drill pipe 22. In another embodiment of the disclosure, adownhole motor 55 (mud motor) is disposed in the drilling assembly 90 torotate the drill bit 50 and the drill pipe 22 is rotated usually tosupplement the rotational power, if required, and to effect changes inthe drilling direction.

In an exemplary embodiment of FIG. 1, the mud motor 55 is coupled to thedrill bit 50 via a drive shaft (not shown) disposed in a bearingassembly 57. The mud motor rotates the drill bit 50 when the drillingfluid 31 passes through the mud motor 55 under pressure. The bearingassembly 57 supports the radial and axial forces of the drill bit. Astabilizer 58 coupled to the bearing assembly 57 acts as a centralizerfor the lowermost portion of the mud motor assembly.

In one embodiment of the disclosure, a drilling sensor module 59 isplaced near the drill bit 50. The drilling sensor module containssensors, circuitry and processing software and algorithms relating tothe dynamic drilling parameters. Such parameters typically include bitbounce, stick-slip of the drilling assembly, backward rotation, torque,shocks, borehole and annulus pressure, acceleration measurements andother measurements of the drill bit condition. A suitable telemetry orcommunication sub 72 using, for example, two-way telemetry, is alsoprovided as illustrated in the drilling assembly 90. The drilling sensormodule processes the sensor information and transmits it to the surfacecontrol unit 40 via the telemetry system 72.

The communication sub 72, a power unit 78 and an MWD tool 79 are allconnected in tandem with the drillstring 20. Flex subs, for example, areused in connecting the MWD tool 79 in the drilling assembly 90. Suchsubs and tools form the bottom hole drilling assembly 90 between thedrillstring 20 and the drill bit 50. The drilling assembly 90 makesvarious measurements including the pulsed nuclear magnetic resonancemeasurements while the borehole 26 is being drilled. The communicationsub 72 obtains the signals and measurements and transfers the signals,using two-way telemetry, for example, to be processed on the surface.Alternatively, the signals can be processed using a downhole processorin the drilling assembly 90.

The surface control unit or processor 40 also receives signals fromother downhole sensors and devices and signals from sensors S₁-S₃ andother sensors used in the system 10 and processes such signals accordingto programmed instructions provided to the surface control unit 40. Thesurface control unit 40 displays desired drilling parameters and otherinformation on a display/monitor 42 utilized by an operator to controlthe drilling operations. The surface control unit 40 typically includesa computer or a microprocessor-based processing system, memory forstoring programs or models and data, a recorder for recording data, andother peripherals. The control unit 40 is typically adapted to activatealarms 44 when certain unsafe or undesirable operating conditions occur.

A suitable device for use of the present disclosure is disclosed in U.S.Pat. No. 6,215,304 to Slade, the contents of which are fullyincorporated herein by reference. It should be noted that the devicetaught by Slade is for exemplary purposes only, and the method of thepresent disclosure may be used with many other NMR logging devices, andmay be used for wireline as well as MWD applications.

It should be noted that underbalanced drilling is commonly carried outusing a coiled tubing instead of a drillstring. Hence the disclosure ofthe BHA being conveyed on a drillstring is not to be construed as alimitation. For the purposes of the present disclosure, the term“drilling tubular” is intended to include both a drillstring as well ascoiled tubing.

Referring now to FIG. 2, the tool has a drill bit 107 at one end, asensor section 102 behind the drill head, and electronics 101. Thesensor section 102 comprises a magnetic field generating assembly forgenerating a B₀ magnetic field (which is substantially time invariantover the duration of a measurement), and an RF system for transmittingand receiving RF magnetic pulses and echoes. The magnetic fieldgenerating assembly comprises a pair of axially spaced main magnets 103,104 having opposed pole orientations (i.e. with like magnetic polesfacing each other), and three ferrite members 109, 110 axially arrangedbetween the magnets 103, 104. The ferrite members are made of “soft”ferrite which can be distinguished over “hard” ferrite by the shape ofthe BH curve which affects both intrinsic coercivity (H_(j) theintersection with the H axis) and initial permeability (μ_(i), thegradient of the BH curve in the unmagnetized case). Soft ferrite μ_(i)values typically range from 10 to 10000 whereas hard ferrite has μ₁, ofabout 1. Therefore the soft ferrite has large initial permeability(typically greater than 10, preferably greater than 1000). The RF systemcomprises a set of RF transmit antenna and RF receive antenna coilwindings 105 arranged as a central “field forming” solenoid group 113and a pair of outer “coupling control” solenoid groups 114.

The tool has a mud pipe 160 with a clear central bore 106 and a numberof exit apertures 161-164 to carry drilling mud to the bit 107, and themain body of the tool is provided by a drill collar 108. Drilling mud ispumped down the mud pipe 160 by a pump 121 returning around the tool andthe entire tool is rotated by a drive 120. Coiled tubing or adrillstring may be used for coupling the drive to the downhole assembly.

The drill collar 108 provides a recess 170 for RF transmit antenna andRF receive antenna coil windings 105. Gaps in the pockets between thesoft ferrite members are filled with non-conducting material 131, 135(e.g: ceramic or high temperature plastic) and the RF coils 113, 114 arethen wound over the soft ferrite members 109, 110. The soft ferrites109, 110 and RF coil assembly 113, 114 are pressure impregnated withsuitable high temperature, low viscosity epoxy resin (not shown) toharden the system against the effects of vibration, seal againstdrilling fluid at well pressure, and reduce the possibility ofmagnetoacoustic oscillations. The RF coils 113, 114 are then coveredwith wear plates 111 typically ceramic or other durable non-conductingmaterial to protect them from the rock chippings flowing upwards pastthe tool in the borehole mud.

Because of the opposed magnet configuration, the device of Slade has anaxisymmetric magnetic field and region of investigation 112 that isunaffected by tool rotation. Use of the ferrite results in a region ofinvestigation that is close to the borehole. This is not a major problemon a MWD tool (except for special situations discussed below that arethe focus of this disclosure) because there is little invasion of theformation by borehole drilling fluids prior to the logging. The regionof investigation is within a shell with a radial thickness of about 20mm and an axial length of about 50 mm. The gradient within the region ofinvestigation is less than 2.7 G/cm. It is to be noted that these valuesare for the Slade device and, as noted above, the method of the presentdisclosure may also be used with other suitable NMR devices. This fieldgradient of less than 2.7 G/cm may be considered to be a “near zero”field gradient for the purposes of the present disclosure as discussedbelow.

Two magnetic fields are used to conduct a typical NMR measurement: astatic magnetic field B₀ and an alternating magnetic field B₁ having acomponent orthogonal to B₀. Pulsed NMR is used in which the alternatingfield B₁ is applied into the sample as a sequence of bursts (usuallycalled pulses):

TW−TP−T ₁−(RP−T ₂−echo−T₂)_(n)

wherein TW is a (long) wait time of usually several times the spinlattice relaxation time, TP is a tipping pulse for tipping the nuclearspins at an angle substantially equal to ninety degrees to causeprecession thereof, T ₁, T ₂ are waiting times, RP is a refocusing pulsefor tipping the nuclear spins greater than 90° and n is the number ofechoes to be acquired in one sequence. The duration of the eventsbetween the echos is called the interecho time TE. The echoes manifestthemselves as rotating macroscopic magnetizations and can be detectedwith a receiver coil. The induced voltages/currents in this coil are thedesired NMR signals. In order to obtain NMR signals and refocus themcorrectly, it is important to adhere to NMR resonance conditions, i.e.B₀ and B₁ amplitudes as well as pulse phases and shapes need to bechosen correctly as known to people familiar with the art of NMR. Anexemplary optimized echo sequence called ORPS is discussed, for example,in Hawkes '013. In the ORPS sequence, the tipping pulse is typically90°, but the refocusing pulses are less than 180°. This is in contrastto the CPMG sequence in which the refocusing pulses are 180° pulses.

Generally, the geometry of the NMR measurement device gives rise to avolume in the earth formation where the B₀ field has the correctstrength to fulfill a resonance condition and in which an RF field canbe presented with a substantial strength and orientation to reorientnuclear spins within the volume. This volume is often referred to as thesensitive volume. For a tool in motion, as the tool moves axially, thevolume containing those protons excited by the excitation pulse (firstpulse of the echo sequence) moves away from the sensitive volume. Hence,the number of spins available to contribute to the subsequent NMR signalis reduced with each subsequent echo. As a consequence, those echoesobtained later in an echo sequence with axial tool motion appear smallcompared to those echoes obtained later in an echo sequence acquiredwith no tool motion. “Later echoes” does not mean that only the lastechoes of a sequence are affected. In fact, the loss of signal startsright at the beginning of a sequence and develops over time in a uniquepattern. This phenomenon is called outflow.

In general, NMR echo sequences are repeated several times for thepurpose of increasing the final signal-to-noise ratio. Even withoutconcern over signal-to-noise ratio, an echo sequence is usually repeatedat least once in order to form a phase-alternated pair (PAP) for thepurpose of removing offset and ringing effects.

At the end of a sequence obtained with axial tool motion, themagnetization of the sensitive volume is substantially zero. A wait timeTW during which re-magnetization of the formation occurs is used as partof the sequence of pulses. Choosing a wait time of at least 5 times thelongest T₁ of the formation ensures that the formation is fullymagnetized (>99% magnetization) immediately prior to the excitationpulse of the ensuing sequence. However, shorter wait times are oftenchosen in order to achieve a higher NMR data rate, leading to animproved axial resolution or signal-to-noise ratio. The drawback ofshortening TW is that the formation may not be fully magnetizedimmediately prior to the ensuing sequence. As a consequence, the totalporosity that is measured in a tool having axial motion can be too low,and the measured T₂-distribution is generally distorted, mainly for thelonger T₂ components.

Similar considerations are present in the radial direction due to radialfluid flow into the borehole. A result of the radial inflow of fluid isan outflow of polarized nuclei from the region of examination, as forthe case of vertical tool movement discussed above. By reducing thefield gradient, the “outflow effect” can be reduced. In the presentdisclosure, the tool is designed in such a way as to maintain close to azero static field gradient in the radial direction, thus minimizingradial motion effects in the NMR signal. In addition to the outfloweffect, motion causes a distortion of the phases of the NMR signals,which also reduces the amplitude of the received NMR signal. The phasedistortion can be reduced by reducing the static magnetic field gradientbut also by reducing the interecho time TE.

A similar solution can be used for a different problem, that of makingNMR measurements in small boreholes. A BHA designed for use in a smallborehole is limited to a small magnet size, so that a normal tool wouldhave a small region of investigation. With small sensitive regions it isdifficult to achieve a sufficient signal to noise ratio, which isrequired to have a high accuracy of the measurement combined with a goodvertical resolution. In addition to or instead of expanding the radialextent of the zone of near zero field gradient, one embodiment of thedisclosure combines multiple resonance areas to one big sensitiveregion, where the measurement is carried out. This combination can bedone by designing one common antenna covering all areas.

FIG. 3 shows an exemplary logging tool 301. Three magnets 303 are shown.Adjacent magnets have like poles facing each other so as to define tworegions of examination 309 a, 309 b. Antennas 307 are used forgenerating the RF pulses and measuring the spin echo signals. Theelectronics module 305 that includes a processor is used for processingthe signals received by the antennas. In the configuration shown, thesignals from the two antennas are summed, so that effectively, signalsfrom a region of examination that is a combination of 309 a and 309 bare obtained. This increases the signal to noise ratio, but also reducesthe vertical resolution of the NMR measurements. For the purposes of thepresent disclosure, the BHA may be considered to be a “carrier” and themagnet assembly produces a static magnetic field in one or more regionsof examination. The static field gradient in the region of examinationis nearly zero, so that during the length of the pulse sequence given byeqn. (1), the “outflow” effect is small and signals are obtained fromnuclear spins that have been polarized. Another factor to be consideredis that the outflow during the time TE should also be small, so that thespin echo signals are without phase distortion.

It is to be noted that the example given in FIG. 3 is directed towardsthe problem of obtaining an adequate signal in a small borehole.Basically the same design with a single region of examination can beused to address the problem of fluid inflow by selecting the combinationof field gradient, and echo train length to satisfy the outflowcondition.

In an alternate embodiment of the disclosure, using two independentantennas, the spin echo signals from 309 a and 309 b are storedseparately in the electronics module. Depth determinations may beconveniently made by having synchronized clocks downhole and upholem andmeasuring the length of the drill string at the surface. When drillinghas progressed so that the measurements made in one region ofexamination (say 309 b) are at the same depth as those made earlier inthe other region of examination (say 309 a), then the data correspondingto the same depth are combined. This method of summing data from thesame depth increases the signal to noise ratio without reducing thevertical resolution.

If the formation contains gas which is flowing to the borehole becausethe pressure in the borehole is lower than the pressure in theformation, we may measure the NMR-properties in a transient zone.Applying a tool with several resonance areas as shown in FIG. 4, havingdifferent depths of investigation, would allow characterizing thetransition zone. Shown in FIG. 4 a is a tool with three regions ofinvestigation 409 a, 409 b and 409 c that can be obtained using a tool401 having four magnets 403 and three RF coils 407. Different depths ofinvestigation can be obtained by changing the static magnetic field(using different magnet configurations)

In an alternate design shown in FIG. 4( b), a pair of magnets 453 andone antenna 457 can be configured to get NMR signals from a multitude ofsensitive regions 459 a, 459 b, 459 c having different radial depths ofinvestigation. The different sensitive regions may be selected by usingdifferent carrier frequencies for the radio-frequency magnetic field.

Measurements made in the different regions can be used to yield a goodestimate of formation properties. If the formation contains gas which isflowing to the borehole because the pressure in the borehole is lowerthan the pressure in the formation, we may measure the NMR-properties ina transient zone. This is illustrated in FIG. 5. FIG. 5( a) shows threedifferent regions of examination. FIG. 5( b) shows an exemplary T₂distribution 501 estimated from signals from the first region, FIG. 5(c) shows an exemplary T₂ distribution 503 estimated from signals fromthe second region, and FIG. 5( d) shows an exemplary T₂ distribution 505estimated from signals from the third region. FIG. 5( e) shows estimatedporosities 511, 513, 515 from FIGS. 5( b), 5(c) and 5(d) respectivelyplotted as a function of distance from the borehole. The radialvariation of estimated porosity is, of course, not real. The NMR signalamplitude decreases near the borehole due to a formation of gas bubbles.This appears as an apparent porosity decrease, while, in fact, it is thehydrogen index of the fluid that decreases on approaching the borehole.Extrapolation of these estimated porosities away from the borehole givesan estimate of the true porosity of the formation.

Turning to FIG. 6, a schematic flow chart illustrates differentformation properties that can be estimated from NMR measurements atdifferent depths of investigation. NMR measurements are made at aplurality of depths of investigation 601 and the borehole pressure ismeasured 603. From these, it is possible to estimate the formationpermeability from T₁ or T₂. The permeability can be estimated usingCoates' method, or a value from an offset well may be used. It is alsopossible to determine the fluid volume in the pore space, compressiblegas volume and porosity at each of the depths of investigation andextrapolate to the formation away from the borehole as discussed above:methods for estimation of water saturation, oil saturation, gassaturation and porosity from T₂ distributions are known in prior art. Bymaking these measurements at different axial depths of the BHA, a log ofeach of these properties can be obtained even while drilling withunderbalanced mud borehole pressure. Of particular interest withunderbalanced drilling is the ability to identify a radial distance fromthe borehole at which the formation fluid reaches the bubble point. Thismanifests itself in a non-zero gas saturation or a reducing apparentporosity. When the bubble point is reached far from the borehole, thisis a warning signal that a potential gas kick could be large and, as aremedial measure, the mud weight should be increased.

Turning now to FIG. 7, different hardware modifications to the basictool of FIG. 2 are discussed to increase the radial size of the regionof investigation. FIG. 7( a) shows the important components of the NMRtool. They are the permanent magnets 701, the soft magnetic antenna core703 and the RF antenna 705. In FIG. 7( b), the length of the antennacores is reduced relative to the length in FIG. 7( a). In FIG. 7( c),thickness of the antenna cores is reduced relative to FIG. 7( a). InFIG. 7( d), the gap between the magnets and the antenna core isincreased relative to FIG. 7( a). In FIG. 7( e), the gap between themagnets and the antenna core are the same as in FIG. 7( a) while thecross sectional area of the magnets is reduced. All of these designmodifications result in different sizes of the region where the magneticfield gradient is near zero.

The disclosure has been described with reference to a NMR device that ispart of a BHA conveyed on a drillstring. The disclosure is equallyapplicable for NMR devices conveyed on coiled tubing. The processingdescribed herein may be done using a downhole processor and the resultsstored on a suitable memory downhole or telemetered to the surface.Alternatively, the data may be stored on a downhole memory and processedwhen the BHA is tripped out of the borehole. With improved telemetrycapability, it should be possible to telemeter the NMR measurements to asurface location and do the processing there.

The results of the processing may be used to estimate, using knownmethods, properties of interest such as a T₂ distribution, volumetrics,permeability, bound volume irreducible, effective porosity, bound water,clay-bound water, total porosity, pore size distribution, and other rockand fluid properties that are based on NMR data. These are all used inreservoir evaluation and development.

The processing of the data may be conveniently done on a processor. Theprocessor executes a method using instructions stored on a suitablecomputer-readable medium product. The computer-readable medium mayinclude a ROM, an EPROM, an EAROM, a flash memory, and/or an opticaldisk.

While the foregoing disclosure is directed to the specific embodimentsof the disclosure, various modifications will be apparent to thoseskilled in the art. It is intended that all such variations within thescope and spirit of the appended claims be embraced by the foregoingdisclosure.

1. An apparatus configured to evaluate an earth formation, the apparatuscomprising: a carrier configured to be conveyed in a borehole in theearth formation; a magnet assembly on the carrier configured to producea static magnetic field in the earth formation and define a plurality ofregions at different radial distance from the borehole; at least oneantenna on the carrier configured to be activated with at least onepulse sequence, the at least one pulse sequence configured to produce asignal from nuclear spins from an associated one of the plurality ofregions of examination; and a processor configured to estimate a valueof a property of the earth formation at the different radial distancesusing the produced signal from each of the plurality of regions ofexamination.
 2. The apparatus of claim 1 wherein the pulse sequence isof the form:TW−TP−τ₁−(RP−τ₂−echo−τ₂)_(n) wherein TW is a (long) wait time of usuallyseveral times a spin lattice relaxation time, TP is a tipping pulse fortipping the nuclear spins at an angle substantially equal to 90° tocause precession thereof, τ₁, τ₂ are waiting times, RP is a refocusingpulse for tipping the nuclear spins greater than 90° and n is the numberof echoes to be acquired in one sequence.
 3. The apparatus of claim 1wherein the plurality of regions are axially spaced apart along theborehole.
 4. The apparatus of claim 1 wherein the plurality of regionsare at substantially the same axial position along the borehole andwherein the at least one pulse sequence further comprises a plurality ofpulse sequences each having an associated frequency.
 5. The apparatus ofclaim 1 wherein a length of the at least one pulse sequence is selectedto suppress the effect on the produced signal due to a fluid flow causedby an excess of a formation fluid pressure over a borehole fluidpressure.
 6. The apparatus of claim 1 wherein an interecho time TE ofthe pulse sequence is selected to suppress the effect on the producedsignal due to a fluid flow caused by an excess of a formation porepressure over a fluid pressure in the borehole.
 7. The apparatus ofclaim 1 wherein the estimated value of the property further comprises anapparent porosity and the processor is further configured to use theestimated value of the apparent porosity for at least one of: (i)estimating a fluid saturation in the formation away from the borehole,(ii) producing a signal indicative of a gas kick, and (iii) estimating atrue porosity of the earth formation.
 8. The apparatus of claim 7wherein the processor is further configured to estimate a value of aproperty of the earth formation selected from: (i) T₂ distribution, (ii)volumetrics, (iii) a permeability, (iv) a bound volume irreducible, (v)effective porosity, (vi) bound water, (vii) clay-bound water and (viii)total porosity.
 9. The apparatus of claim 1 wherein the carrier furthercomprises a bottomhole assembly configured to be conveyed on a drillingtubular into the borehole.
 10. A method of evaluating an earthformation, the method comprising: conveying a carrier into a borehole inthe earth formation; using a magnet assembly on the carrier forproducing a static magnetic field in the earth formation and defining aplurality of regions at different radial distance from the borehole;activating at least one antenna on the carrier with at least one pulsesequence, the at least one pulse sequence configured to produce a signalfrom nuclear spins from an associated one of the plurality of regions ofexamination; and using a processor for estimating a value of a propertyof the earth formation at the different radial distances using theproduced signal from each of the plurality of regions of examination;11. The method of claim 10 wherein the pulse sequence is of the form:TW−TP−τ₁−(RP−τ₂−echo−τ₂)_(n) wherein TW is a (long) wait time of usuallyseveral times a spin lattice relaxation time, TP is a tipping pulse fortipping the nuclear spins at an angle substantially equal to 90° tocause precession thereof, τ₁, τ₂ are waiting times, RP is a refocusingpulse for tipping the nuclear spins greater than 90° and n is the numberof echoes to be acquired in one sequence.
 12. The method of claim 10further comprising using the magnet assembly for defining the pluralityof regions as axially spaced apart along the borehole.
 13. The method ofclaim 10 further comprising: using the magnet assembly for defining theplurality of regions at substantially the same axial position along theborehole; and using, for the at least one pulse sequence, a plurality ofpulse sequences each having an associated frequency.
 14. The method ofclaim 10 further comprising selecting a length of the at least one pulsesequence for suppressing the effect on the produced signal due to afluid flow caused by an excess of a formation pore pressure over aborehole fluid pressure.
 15. The method of claim 10 further comprisingselecting an interecho time TE of the pulse sequence for suppressing theeffect on the produced signal due to the fluid flow caused by an excessof a formation pore pressure over a fluid pressure in the borehole. 16.The method of claim 10 wherein the estimated value of the propertyfurther comprises an apparent porosity, the method further comprising:using the processor for at least one of: (i) estimating a fluidsaturation in the formation away from the borehole, (ii) producing asignal indicative of a gas kick, and (iii) estimating a true porosity ofthe earth formation.
 17. The method of claim 16 further comprisingaltering a mud weight used for drilling operations.
 18. The method ofclaim 10 further comprising: using, as the carrier, a bottomholeassembly; and conveying the bottomhole assembly on a drilling tubularinto the borehole.
 19. A computer-readable medium product having storedthereon instructions that when executed by a processor cause theprocessor to execute a method, the method comprising: estimating a valueof a property of the earth formation at each of a plurality of regionsof examination at different radial distances from a borehole usingsignals produced signal from each of the plurality of regions ofexamination responsive to activation of at least one antenna with atleast one pulse sequence, the at least one pulse sequence configured toproduce a signal from nuclear spins from an associated one of theplurality of regions of examination.
 20. The medium of claim 19 furthercomprising at least one of: (i) a ROM, (ii) an EPROM, (iii) an EAROM,(iv) a flash memory, and (v) an optical disk